When a well is first drilled and put into operation, the reservoir pressure in the well is generally sufficient to cause oil and/or gas contained in the well to rise to the surface where it is collected and stored. As the well ages and more wells are placed into a common basin, the well's ability to maintain the pressure necessary to continuously pump oil and/or gas declines due to natural pressure depletion. Once the reservoir pressure is no longer sufficient to permit continuous pumping, a well operator must either install an artificial lift system or cap the well. If a sufficient reserve of oil or gas remains in the reservoir, capping the well may not be economically desirable.
One method of artificial lift is to place a pump in the well to mechanically pump the oil and/or water from the well. However, this can be a very expensive proposition not only requiring an operator to install a pumping system, but also to provide a source of power to run the pump. As can be appreciated, many wells are located in remote locations where sources of energy are not easily or inexpensively recovered. Typically, mechanical pump lift systems are only utilized on wells where the volume of the reserve accessible by the well is considerable enough to justify the expensive of fitting the well with the expensive pumping system and to justify the increased operational expenses.
For wells that are not amenable to a mechanical pumping lift system, a plunger lift system is often used. Plunger lift systems are passive in that they do not rely on an external power source for their operation. Rather, they utilize any remaining well reservoir pressure combined with the well's ability to re-pressurize when the valve connecting the well to the collection tanks or flowline is closed.
Plunger lift systems are generally inexpensive to purchase, as well as, operate compared to alternative types of artificial lift systems. External power is required only for the operation of a small number of solenoids, valve motors and the system's electronic controller. The power levels are low enough that only a small battery pack is necessary.
A well 10 outfitted with a typical plunger lift system is illustrated in FIG. 1. The well comprises a borehole 12 that extends from the subterranean surface to a reserve of oil and/or natural gas. The borehole comprises a tubing string 14 that is encircled by casing 16. The tubing string is comprised of a plurality of tubes interconnected by collar joints (not shown) at their respective ends. A plunger 44 is located in the tubing and is adapted to move freely upwardly and downwardly between the wellhead 18 and the well bottom 20. A bumper 22, most commonly a coil spring, is located at the well bottom to stop the plunger as it completes its descent.
A typical Christmas tree 24 of a plunger lift outfitted well includes a lubricator/catcher 26 that stops the upwardly ascent of the plunger. An arrival sensor 28 is provided at the base of the lubricator/catcher to sense the arrival of the plunger and activate a catcher solenoid 30 to hold the plunger in place until selectively released to travel back to the well bottom. In other variations, a spring-loaded catch arm (not illustrated) is biased into the interior of the lubricator/catcher at its base to catch and hold the plunger once it passes the arm, wherein a plunger solenoid attached to the arm pulls it back and out of the interior to release the plunger. In another variation, it is not necessary to catch the plunger at the surface as the plunger is held in the lubricator until the pressure level dissipates and the plunger falls back to the bottom. Additionally, in this variation shutting a flow line valve will also cause the plunger to fall. A flow line 32 is in operable fluid communication with the tubing string 14 and the solenoid-operated (or motor-operated) flow valve 34, which when opened permits the flow of oil and/or gas to storage tanks (not illustrated) or pipeline (not illustrated). A pressure sensor 38 is also provided to measure the pressure level within the casing.
The arrival sensor 28, the plunger solenoid 30, the flow valve 34 and the pressure sensor 38 are all electronically coupled with a controller module 40. Based on input from the pressure sensor and other sensors and/or the travel time of the plunger, the controller may catch or release the plunger and opens or closes the flow valve to control the lifting of oil and gas out of the well. If no power source is readily available, a solar panel 42 and a battery pack (not illustrated) can be provided to power the controller and the various solenoids and sensors.
FIG. 2 (prior art) is an isometric view of a typical plunger 44. There are many different types of plungers depending on a particular design application and engineering variable concerning the well and any debris or contaminants that might be found in the well. Generally, a plunger is an elongated primarily metallic cylinder or rod that has an outside diameter only slightly smaller than the internal diameter of the tubing string 14. The illustrated plunger generally comprises a plurality of annular wiper ridges 50 that are spaced along most of the plunger's length. The ridges help scrape sand and scale not to mention paraffin and other debris from the sidewalls of the tubing string during the plunger's ascent and descent. Other types of plungers (not illustrated) can have, but are not limited to, (i) smooth outside diameter surface, (ii) spring-loaded metal plates that contact the surface of the tubing string's interior wall, and/or (iii) a segment made of bristles that scrape the tubing string's interior wall. Further, plungers can be flexible to permit them to negotiate around non linear portions of the tubing string during their journey.
A plunger can be solid or it can have a hollow interior. The illustrated plunger is of the hollow variety having an at least partially open bottom end 52 and a plurality of small holes 54 extending inwardly to the interior 56 from between the annular ridges 50.
Some plungers also include a valve at the top of the interior that is in fluid communication with the plunger's topside and that permits the gas and fluids to pass freely through the interior of the plunger when it is open. The valve is opened as the plunger is released from the lubricator/catcher 26 and facilitates the rapid descent of the plunger down the well. When the plunger impacts the bumper 22 at the well bottom 20, the valve closes.
At the top of the illustrated plunger, a fishing neck 58 is shown. The fishing neck permits the well operator to easily retrieve the plunger should it become stuck in the tubing string 14. An operator snakes a wire line with a suitable clamp member down the well to couple with the fishing neck and permit the plunger to be pulled free. As can be appreciated, having to pull tubing to remove a stuck plunger from a well results in downtime that the well could otherwise be producing. The build up of paraffin and other debris, especially around tubing collar joints, can build up over time and can eventually cause a plunger to become stuck. If the operator can determine that there is a debris buildup, an operator would swap out the plunger with a cleaning plunger, such as a brush plunger, to clean the tubing string rather than risk significant downtime if and when the plunger becomes stuck.
Prior art FIG. 3 is a flow chart indicating the operation of controller of a typical plunger lift system equipped well. Once the pressure level in a gas or oil well has dropped to a level that no longer supports the extraction of the oil and/or gas as measured by a pressure sensor 38, the flow valve 34 is closed as is indicated by block 100 and the catcher solenoid 30 may be activated, if necessary, to free the plunger 44 from the lubricator/catcher as indicated in block 105. The plunger descends down the borehole 12 until impacting the bumper 22 and coming to rest at the well bottom 20.
While the plunger 44 is resting on the well bottom 20, pressure in the well increases and is monitored. In an oil well, oil accumulates in the well and percolates past the plunger to fill a portion of the tubing 14. This oil is lifted out of the well when the plunger ascends to the surface. In a primarily gas well, liquids (typically condensate and water) accumulate above the plunger and the casing causing a liquid loading condition. If the liquids are not removed from the tubing string 14, the well can become “loaded up” and cease to produce due to excessive hydrostatic head.
Once sufficient time has elapsed, the pressure in the well reaches a suitable level as measured at the wellhead 18 by the pressure sensor 38, the controller opens the flow valve 34 as indicated in block 115. Almost immediately a pressure differential is established between the portion of the tubing string 14 above the plunger 44 and the region below the plunger causing the plunger to be propelled upwardly carrying any liquid located above the plunger with it. Accordingly, the liquid is moved into the flow line 32 for storage or disposal. Once the plunger passes the arrival sensor 28, it is held in the lubricator/catcher 26 (i) through the activation of the catch solenoid 30, (ii) by way of the spring-loaded catch arm, or (iii) by gas pressure from below as indicated in block 120.
Generally, the plunger will remain in the lubricator/catch as long as the well continues to produce. The controller 40 will monitor the pressure in the well via the pressure sensor 38 as indicated in block 125. Additionally, if the well is equipped with a flow sensor, the flow rate in the flow line 32 can also be monitored. After a certain period of time has passed, however, the pressure in the well and the flow rate will drop to a level that will not support extraction of oil and/or gas and the controller will shut the flow valve 34 releasing the plunger again to repeat the process.